Water detection and 3-phase fraction measurement systems

ABSTRACT

Methods and apparatus enable monitoring a hydrocarbon well for water within a flow stream of the well. A water detector includes a light source for emitting into a flow stream infrared light that includes a water absorbent wavelength band. A detector detects attenuation of the water absorbent wavelength band upon the infrared radiation passing through at least a portion of the flow stream. The water detector outputs a presence of water and/or a phase fraction or quantification of water as determined based on the attenuation. Detecting attenuation of a substantially transmissive wavelength band with respect to water simultaneously with detection of the attenuation of the water absorbent wavelength band can enable correction for non-wavelength dependent attenuation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of co-pending U.S. patent applicationSer. No. 11/625,427, filed Jan. 22, 2007, which as acontinuation-in-part of U.S. patent application Ser. No. 11/065,489,filed Feb. 24, 2005 and issued as U.S. Pat. No. 7,233,001, which areboth herein incorporated by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the invention generally relate to flow analysis.

2. Description of the Related Art

Oil and/or gas operators periodically measure water/oil/gas phasefractions of an overall production flow stream in order to aid inimproving well production, allocating royalties, properly inhibitingcorrosion based on the amount of water and generally determining thewell's performance. Various approaches for analyzing the phase fractionof such flow streams exist and include full or partial phase separationand sensors based on capacitive, density and microwave measurements.However, known measurement techniques suffer from their own uniquedrawbacks and/or limitations.

Wells often produce water along with hydrocarbons during normalproduction from a hydrocarbon reservoir within the earth. The waterresident in the reservoir frequently accompanies the oil and/or gas asit flows up to surface production equipment. Onset of water in gas wellsand wet gas wells introduces the prospect of ice-like hydrate formation,which can plug lines and create unsafe flowing conditions. Water in theproduction flow at low temperatures such as less than 15° C. as occursin seawater applications may cause formation of the hydrates dependingon volume and pressure of the flow. Furthermore, gas wells that areoften high rate produce large pressure drops across chokes and flow areachanges. At these locations, Joule Thompson cooling can reducetemperatures significantly which may result in severe hydrate problemsin a matter of hours or even minutes if water is present. Seriousproblems result once the hydrates form and block or limit flow.Continuous measurement of phase fraction rather than, for example,monthly testing can improve operations such as hydrate prevention aswell as reservoir management and allocations.

Some approaches utilize chemical injection to inhibit gas hydrateformation in case of any potential water breakthrough that may not bedetected. However, cleaning and treatment procedures required at surfaceto remove the hydrate inhibitor along with high costs of the inhibitoritself contribute to production expenses. Therefore, injection ofmethanol as an exemplary hydrate inhibitor unnecessarily increases costswhen preformed even if water is not present or when done at levelsbeyond that required based on the water that is present.

Therefore, there exists a need for an improved water detector andoverall phase fraction measurement to enable, for example, flowassurance, improved reservoir management, and improved allocation from aproducing well. There exists a further need for an improved infraredoptical detector, such as a water detector that provides the flowassurance or other flow related information with improved sensitivityand accuracy.

SUMMARY OF THE INVENTION

Methods and apparatus generally relate to monitoring a hydrocarbon wellfor water within a flow stream of the well. A water detector includes alight source for emitting into a flow stream infrared light thatincludes a water absorbent wavelength band. A detector measures thetransmitted light of the water absorbent wavelength band passing throughat least a portion of the flow stream. The water detector outputs apresence of water and/or a phase fraction or quantification of water asdetermined based on the attenuation. Measuring attenuation of asubstantially transmissive wavelength band with respect to watersimultaneously with measurement of the attenuation of the waterabsorbent wavelength band can enable correction for non-wavelengthdependent attenuation. Some embodiments may include a hydrocarbonabsorbent wavelength band and/or, in some instances, a second waterabsorbent peak that can differentiate water from alcohols.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 is a schematic diagram of a well testing system that includes aninfrared phase fraction meter in accordance with embodiments of theinvention.

FIG. 2 is a partial section view of an infrared phase fraction meterhaving a probe end inserted into a pipe.

FIG. 3 is an exploded view of internal components of the infrared phasefraction meter illustrated in FIG. 2.

FIG. 3A is an end view of a connector taken across line 3A-3A in FIG. 3.

FIG. 4 is a flow chart of a flow processing technique performed by thephase fraction meter and a flow computer of FIG. 1.

FIG. 5 is a graph illustrating absorption of two types of oil, water andcondensate for an infrared region and wavelengths thereof selected forinterrogation via channels of an infrared phase fraction meter.

FIG. 6 is a graph illustrating absorption of two types of oil, water andcondensate for an infrared region and wavelengths of the infrared regionselected for interrogation via channels of an infrared water detector.

FIG. 7 is a flow chart of a flow processing technique to detect apresence of water utilizing the water detector.

DETAILED DESCRIPTION

Embodiments of the invention generally relate to water detectors thatutilize infrared optical analysis techniques. While the water detectoris illustrated herein as part of a test system that is also capable ofdetecting phase fractions from a flow stream being produced from a well,use of the water detector includes various other applications and canprovide moisture detection without requiring water quantification orsuch further phase fraction detection. For example, other industriessuch as pharmaceutical, food, refinery, chemical, paper, pulp,petroleum, gas, mining, minerals and other fluid processing plants oftenutilize flow assurance systems in order to detect whether or not wateris present at all.

FIG. 1 shows a well testing system 100 including an infrared phasefraction meter 101 in accordance with embodiments of the invention. U.S.Pat. Nos. 6,076,049 and 6,292,756, which are herein incorporated intheir entirety, further describe examples of infrared water fractionsystems such as the testing system 100. The well testing system 100takes a production flow directly from a well or from a common gatheringstation (not shown) that provides a manifold to direct one well at atime to the testing system 100 while production from a plurality ofother wells is directed to a production line by bypassing the testingsystem 100. The testing system 100 includes a separator 102, a gas flowmeter 104, a liquid flow meter 106, an optional mixer 108, the infraredphase fraction meter 101 and a flow computer 110. For some embodimentsand applications, the separator 102 and the gas flow meter 104 may notbe required as will be apparent from the following discussion. Theseparator 102 divides the production flow into a liquid portion 112 thatincludes water content and oil content of the production flow and a gasportion 114 that includes gas content of the production flow.

The gas flow meter 104 measures flow through a gas stream 115. On theother hand, a flow stream 116 passes from the liquid portion 112 of theseparator 102 to the liquid flow meter 106 and the infrared phasefraction meter 101. The flow stream 116 often includes some gases evenafter being separated and may even be a fluid stream that has not beenseparated. The liquid flow meter 106 detects an overall flow rate of theflow stream 116 without differentiating phases making up the flow stream116. Accordingly, determining a flow rate of individual phases requiresdetermining what percent of the flow stream 116 that each phase makesup. In one embodiment, the infrared phase fraction meter 101 detects awater cut of the flow stream 116. Thus, the phase fraction meter 101along with the liquid flow meter 106 enables calculation of the flowrate of water and oil phases.

In general, the mixer 108 includes any structure or device capable ofmaking the flow stream 116 more homogenous prior to being sampled by theinfrared phase fraction meter 101. For example, a set of axially spacedveins or blades disposed within a flow path of the flow stream 116 formsa static mixer for use as the mixer 108. The phase fraction meter 101may not require incorporation of the mixer 108 within the flow stream116 as would be the case when the flow stream 116 is sufficiently mixed.

FIG. 2 illustrates the phase fraction meter 101 disposed on a pipe 200that carries the flow stream 116 therein. A probe end 202 of the meter101 inserts into the pipe 200 such that a sampling region 204 ispreferably located in a central section of the pipe 200. A body portion212 of the meter 101 couples to the probe end 202 and houses electronics(not shown) and an optional local display 214 outside of the pipe 200.The meter 101 further includes a broad band infrared source 211 coupledto a power supply line 210 and located on an opposite side of thesampling region 204 from a collimator 206 that is coupled to the bodyportion 212 by optical outputs 209 connected thereto by a commonconnector 208 such as a SubMiniature Version A (SMA) connector. For someembodiments, the source 211 includes a tungsten halogen lamp capable ofemitting light in a range of wavelengths that includes particularwavelengths selected for interrogation as discussed in detail below.Input and output wiring connections 216 lead from the body portion 212of the meter 101 for providing power to the meter 101 and communicationwith the flow computer 110 (shown in FIG. 1) and optionally the liquidflow meter 106 (shown in FIG. 1). When the phase fraction meter 101 isconnected to the flow meter 106, the phase fraction meter 101 maycapture flow data from the flow meter 106 as a 4-20 milliamp orfrequency based signal that can be processed and made accessible to theflow computer 110, for example, via the wiring connections 216 using anindustry standard protocol, such as Modbus.

FIG. 3 illustrates internal components of the infrared phase fractionmeter 101 in an exploded view. These components include the source 211,a parabolic reflector 300 for directing light from the source 211, firstand second sapphire plugs 302, 304, the collimator 206 and the opticaloutputs 209 that couple the collimator 206 to infrared filters 308. Anarea between the sapphire plugs 302, 304 defines the sampling region 204where fluid of the flow stream 116 flows across as indicated by arrow303.

In operation, light from the source 211 passes through the firstsapphire plug 302 and through the fluid of the flow stream 116 where thelight is attenuated prior to passing through the second sapphire plug304. Unique absorption characteristics of the various constituents ofthe flow stream 116 cause at least some of the attenuation. Thecollimator 206 adjacent the second sapphire plug 304 focuses andconcentrates the attenuated light into optical outputs 209 via thecommon connector 208. The optical outputs 209 typically include amultitude of optical fibers that are divided into groups 209 a-d.Utilizing one type of standard connector, eighty-four fibers pack withinthe common connector 208 such that each of the four groups 209 a-dcomprise a total of twenty one fibers. However, the exact number offibers and/or groups formed varies for other embodiments.

As illustrated in FIG. 3A by end view 207, the fibers within each of thegroups 209 a-d may be arranged to avoid sampling at discrete zones whichmay be affected by inconsistency of the source 211 and/or isolatedvariations within the flow stream 116. Specifically, each individualfiber receives light transmitted across a discrete light path throughthe fluid that is different from a light path of adjacent fibers. Theend view 207 schematically illustrates fiber ends A, B, C, Dcorresponding to groups 209 a, 209 b, 209 c, 209 d, respectively, andarranged such that each quadrant of the end view 207 includes fibersfrom all groups 209 a-d. For example, one fiber of the group 209 areceives light passing through a path on the left side of the samplingregion 204 while another fiber of the group 209 a receives light passingthrough a path on the right side of the sampling region 204 such thatthe combined light from both fibers is detected. Accordingly, thisarrangement may reduce errors caused by making a measurement at only onediscrete location by effectively averaging the light received from allfibers within the group 209 a.

Each of the four groups 209 a-d connects to a respective housing 310 ofone of the infrared filters 308 via a connector 306 such as an SMAconnector. Each of the infrared filters 308 includes the housing 310, anarrow band pass filter 311 and a photo diode 313. The photo diode 313produces an electrical signal proportional to the light received from arespective one of the groups 209 a-d of the optical outputs 209 afterpassing through a respective one of the filters 311. Preferably, alogamp circuit (not shown) measures the electrical signals to give up tofive decades of range. Each of the filters 311 filters all but a desirednarrow band of infrared radiation. Since each of the filters 311discriminate for a selected wavelength band that is unique to thatfilter, each of the groups 209 a-d represent a different channel thatprovides a total attenuation signal 314 indicative of the totalattenuation of the light at the wavelengths of that particular filter.Thus, the signals 314 a-d from the four channels represent transmittedradiation at multiple different desired wavelength bands.

If only one wavelength is interrogated without comparison to otherwavelengths, absorption based attenuation associated with that onewavelength cannot be readily distinguished from other non-absorptionbased attenuation that can introduce errors in an absorptionmeasurement. However, using multiple simultaneous wavelengthmeasurements provided by the signals 314 a-d from the different channelsenables non-wavelength dependent attenuation, such as attenuation causedby common forms of scattering, to be subtracted out of the measurements.An appropriate algorithm removes these non-absorption backgroundinfluences based on the fact that the non-wavelength dependentattenuation provides the same contribution at each wavelength and thenceat each channel regardless of wavelength dependent absorption. Thus,comparing the signals 314 a-d from each channel at their uniquewavelengths enables correction for non-wavelength dependent attenuation.

Additionally, selection of the filters 311 determines the respectivewavelength for each of the multiple simultaneous wavelength measurementsassociated with the signals 314 a-d from the different channels.Accordingly, the different channels enable monitoring of wavelengths atabsorbent peaks of the constituents of the flow stream 116, such aswater absorbent peaks in addition to oil absorbent peaks, based on thewavelengths filtered. To generally improve resolution, a minute changein the property being measured ideally creates a relatively largesignal. Since the relationship between concentration and absorption isexponential rather than linear, large signal changes occur in responseto small concentration changes of a substance when there is a low cut orfraction of the substance being measured based on attenuation of thesignal from the channel(s) monitoring the wavelengths associated with anabsorbent peak of that substance. In contrast, small signal changesoccur in response to concentration changes of the substance when thereis a high cut of the substance being measured by the same channel(s).

Accordingly, the different channels provide sensitivity for the meteracross a full range of cuts of the substance within the flow, such asfrom 0.0% to 100% phase fraction of the substance. For example,channel(s) with wavelengths at water absorbent peaks provide increasedsensitivity for low water fractions while channel(s) with wavelengths atoil absorbent peaks provide increased sensitivity for high waterfractions. Thus, the channel(s) with the highest sensitivity can beselected for providing phase fraction results or averaged with the otherchannels prior to providing the results in order to contribute to thesensitivity of the meter.

Another benefit of the multiple simultaneous wavelength measurementsprovided by the signals 314 a-d from the different channels includes theability to accurately calibrate the meter 101 with a small amount ofpure fluid. Thus, calibration of the meter 101 does not require areference cut. Selection of wavelengths as disclosed herein for thechannels reduces sensitivity to different types of oil in order tofurther simplify calibration. For example, oils which are light in coloror even clear have an optimal absorption peak around a wavelength of1,750 nanometers, but black oils have stronger absorption around awavelength of 1,000 nanometers. If two of the four channels includefilters at these wavelengths, then the algorithm can determine theoptimal choice at the calibration stage rather than requiring a hardwarechange for different oil types.

FIG. 4 shows a flow chart of a flow processing technique performed bythe phase fraction meter 101 and/or the flow computer 110 (shown inFIG. 1) after emitting infrared radiation into the flow stream 116. Theprocessing begins at a step 400 where electronics receive signals 314a-b from at least two channels of the phase fraction meter 101. In astep 404, an algorithm calculates a phase fraction of at least one phasedue in part on absorption readings for “pure” substances made in acalibration step (not shown). The algorithm corrects the signals fornon-wavelength dependent attenuation based on these influences effectingsignals from each channel indiscriminately such that the non-wavelengthdependent attenuation drops out in the solution of simultaneousequations. For example, a water cut of the flow stream 116 can becalculated by averaging or otherwise combining results fromnon-homogeneous linear equations calculated for each channel, whereinthe equations include detector photocurrent values corrected fornon-wavelength dependent attenuation, an absorption constant, andhardware constants. The following equation defines an exemplary equationthat may be used for calculating the water cut (C_(W)) as measured by asingle channel:

I _(i)=β(I _(oi))e ^(−(α) ^(Oi) ^(x) ^(O) ^(+α) ^(Wi) ^(x) ^(W) ⁾  (1)

x _(O) +x _(W)=1  (2)

where I_(i) represents transmitted light at frequency band i, βrepresents a frequency independent attenuation coefficient, I_(Oi)represents incident light at frequency band i, α_(Oi) represents theabsorption coefficient of the oil at frequency band i, α_(Wi) representsthe absorption coefficient of the water at frequency band i, x_(O)represents the fraction of the path length occupied by oil, and x_(W)represents the fraction of the path length occupied by water. x_(W) isequivalently the water cut “C_(W)” of the mixture. Equations 1 and 2contain three unknowns, x_(O), x_(W), and β. A minimum of twofrequencies are therefore required to solve for C_(W):

$\begin{matrix}{C_{W} = {x_{W} = \frac{{\ln \left\lbrack \frac{I_{2}}{I_{1}} \right\rbrack} - \left( {a_{O\; 1} - a_{O\; 2}} \right)}{\left( {a_{W\; 1} - a_{W\; 2}} \right) - \left( {a_{O\; 1} - a_{O\; 2}} \right)}}} & (3)\end{matrix}$

After receiving data from the flow meter 106 as indicated in a step 406,the flow computer calculates a flow rate of the at least one phase in astep 408.

FIG. 5 illustrates a graph of absorption verses wavelength for two typesof oil indicated by curves 501, 502, water represented by curve 503 andcondensate denoted by curve 504 for an infrared region. Gas providesrelatively zero absorption at typical test line pressures and hasaccordingly been omitted from the graph. The graph shows four preferredwavelength bands 505-508 for filtering by the filters 311 in order toprovide the four channels of the phase fraction meter 101. Otherwavelength bands may be selected without departing from the scope of theinvention. The phase fraction meter 101 essentially ignores salinitychanges since typical salinity levels have negligible effect on waterabsorption over the spectral region of interest. Additionally, lack ofsignificant absorption by gas makes the meter 101 substantiallyinsensitive to free gas in the fluid stream 116.

In general, a first wavelength band 505 includes wavelengths within arange of approximately 900 nanometers (nm) to 1200 nm, for example about950 nm, where there is an oil absorbent peak. A second wavelength band506 includes wavelengths centered around 1450 nm where there is a waterabsorbent peak. A trough around 1650 nm provides another interrogationregion where a third wavelength band 507 generally is centered. A fourthwavelength band 508 generally includes a peak centered about 1730 nmthat is fundamentally associated with carbon-hydrogen bonds of the oil501, 502 and the condensate 504. The substantial similarities and/ordifferences in the absorption of the different phases at each of thebands 505-508 further enables their differentiation from one anotherwith the phase fraction meter 101.

For some embodiments, the flow meter 106 may only provide a mass flowrate instead of a volumetric flow rate. In these embodiments, the phasefraction meter 101 measures the phase fraction as discussed above. Thephase fractions of the oil and water are then multiplied by theirrespective known densities and summed to provide the density of thecombined fluid since the gas density is minimal. The mass flow rate isthen divided by this calculated density of the combined fluid to providean accurate volumetric flow rate.

Exemplary Flow Regimes/Applications

Different flow models or regimes may be useful for flow processingdepending upon the particular application. For example, in anapplication, where gas and water travel at different velocities or wherethe oil travels in slugs through the pipe, a flow model can take theseflow conditions into account. Furthermore, the following sectionsdescribe various additional methodologies for making measurements ofdifferent flow regimes using the meter shown herein. Selecting theappropriate algorithm for given conditions can improve accuracy of themeasurements.

Water cut measurements (i.e., water cut only (water/total liquid ratio)with no measure of the gas phase volume) may be made throughout a widerange of free gas phase content in the stream. Three exemplary flowregimes may be defined as i) dispersed gas bubble in liquid; ii)gas-liquid slugs; and iii) dispersed liquid in gas. The first two flowregimes cover flows where about 0-95% gas volume fraction (GVF) existswhile the last regime includes about 95-99.99% GVF.

Full Range Water Cut (0-100%) with Three Phase Streams (Oil, Water, Gas)where Gas can Represent about 0-95% Gas Volume Fraction (GVF).

Absorbance measurements performed using the meter correspond to afunction which may be defined as:

A _(i)=α_(oi) x _(o)+α_(wi) x _(w) +S  (4)

where:

-   -   A_(i)=total absorbance at wavelength i and includes chemical        (absorption) and physical (scattering) effects;    -   a_(oi)=absorption coefficient for oil at wavelength i;    -   a_(wi)=absorption coefficient for water at wavelength i;    -   x_(o)=pathlength of oil;    -   x_(w)=pathlength of water; and    -   S=scatter contribution to overall absorbance (wavelength        independent).        Instead of utilizing a fixed path length (e.g., Equation 2) in        determining water cut, making three separate absorbance        measurements for three different wavelengths enables solving for        three unknowns (x_(o), x_(w), and S) in Equation 4. This allows        for the potential of increased effective pathlength due to        scattering. This approach works for flow regimes without gas or        with the dispersed gas bubbles in liquid (flow regime i) to        enable calculation of the water cut based on the pathlength of        water x_(w) relative to the total pathlength X_(w)+X_(o).

For the gas-liquid slugs (flow regime ii), the meter suspends analysiswhen recognized, due to the absorbance measurements, that the sensor gapis filled with a gas continuous mix (e.g. all gas or dispersed liquid ingas). The meter bases the water cut determination on measurements takenat intervals when the gap is filled with a liquid continuous mix (e.g.,all liquid or dispersed gas bubble in liquid). Therefore, applyingEquation 4 as described above during these selected intervals associatedwith liquid slugs passing across the meter enables an improvedcalculation for the water cut, which is independent of the quantity ofgas and hence the suspended intervals.

Full Range Water Cut (0-100%) with Three Phase Streams (Oil, Water, Gas)where Gas can Represent about 95-99.99% GVF and Three Phase FractionMeasurement for Full Range Water Cut (0-100%) and 95-99.99% GVF.

With respect to the dispersed liquid in gas (flow regime iii), a flowwith about 95-99.99% GVF defines a flow stream that is gas continuousand is in the “wet gas” region. If three wavelengths are selected wheregas has no absorption, then Equation 4 above can be used to solve forwater cut. If a wavelength is used where gas has some absorption (i.e.high pressure methane at 1730 nm), then the function representing theabsorbance measured may be modified to:

A _(i)=α_(oi) x _(o)+α_(wi) x _(w)+α_(gi) x _(g) +S  (5)

where:

-   -   a_(gi)=gas absorption coefficient at wavelength i; and    -   x_(g)=pathlength of gas.        Solving for the water cut using Equation 5 requires making        absorbance measurements at four wavelengths due to the        pathlength of gas x_(g) representing an additional unknown.        Further, the solution of Equation 5 also yields phase fraction        for oil, water and gas individually.

Three Phase Fraction Measurement for Full Range Water Cut (0-100%) and0-95% GVF.

A further extension of the application of Equation 4 above enablesdetermination of three phase fraction measurements of a flow stream.Solution of Equation 4 provides water content and oil content but notthe gas content. For the dispersed gas bubble in liquid (flow regime i),the gas content can be estimated as:

x _(g)=1−x _(o) −x _(w)  (6)

where the path lengths have been normalized. With respect to thegas-liquid slugs (flow regime ii), the amount of time the sensor gap isgas continuous relative to total time indicates the gas content. Inother words, measuring gas slugs based on the percentage of timeanalysis is suspended enables calculation of the gas content for flowconditions with the gas-liquid slugs (flow regime ii).

Three Phase Fraction-Four Component Measurement for Full Range Water Cut(0-100%) and 95-99.99% GVF.

As described heretofore, embodiments of the invention enable three phasefraction measurements (oil, water, gas) when the flow stream is gascontinuous with dispersed liquid (flow regime iii). Furthermore, theflow stream can contain an injected chemical such as methanol to act asa hydrate inhibitor. The chemical may be miscible in both thehydrocarbon and aqueous phases.

Using n+1 wavelengths or more enables calculating the concentrations ofn components even if one or more of the components are not in separatephases, such as the methanol. Based on the teachings herein, theabsorption coefficients must not be identical for any two componentsover the n+1 wavelengths. For water and methanol (or other alcohols),selection of 1450 nm and 1950 nm for analysis insures differentabsorption coefficient sets.

For some embodiments, concentration measurements in any GVF may be madefor various hydrocarbon components to determine calorimetricmeasurements of fluid flow. For example, gas composition analysis mayinvolve selecting wavelengths to be analyzed for differentiating methanefrom heavier hydrocarbons such ethane or propane. Further, oilcomposition analysis may similarly rely on wavelength selection tofacilitate calorimetric measurement thereof.

Detecting Water Presence

Like FIG. 5, FIG. 6 shows a graph of absorption verses wavelength foroil curves 601, 602, water curve 603 and condensate curve 604 for aninfrared region. A water detector enables performing spectral analysisof sensitive water wavelength peaks along the water curve 603 in orderto provide flow assurance or moisture detection. For some embodiments,the water detector includes identical components as the infrared phasefraction meter 101 (shown in FIGS. 2-3A), which can thereby be operatedas the water detector and/or the phase fraction meter. In other words,the term “water detector” as used herein can but does not necessarilyenable measurement of phase fractions including quantificationsregarding water fractions.

Components of the water detector can be adapted for use in the wellboreor subsea for some embodiments such as applications where immediatewater breakthrough information is required. Further, distance across asampling region of the water detector can be variable, can extend acrossan entire cross-section of a conduit, or can define two or moredifferent path lengths across the sampling region. Selecting theappropriate path length for a particular fluid flow can thereby improvesensitivity of the water detector. For example, selecting a maximum pathlength due to the distance across the sampling region extending acrossthe entire cross-section of the conduit can improve sensitivity wherethe mixture is predominantly gas and hence substantially transmissive.

As shown in FIG. 6, the graph shows examples of first, second, third,fourth and fifth wavelength bands 605-609 for optional filtering byfilters of the water detector in order to provide channels of the waterdetector. Since channels with wavelengths at water absorbent peaksprovide increased sensitivity for low water fractions, the secondwavelength band 606 selected around 1450 nm and/or the fifth wavelengthband 609 selected around 1950 nm enable sensitive presence detectionand/or quantified measurement of water. Absorption characteristicsassociated with H—O—H molecular bending occur at around 1950 nm suchthat water absorbs light in the fifth wavelength band 609. In addition,absorption characteristics due to O—H stretching occur at around 1450 nmsuch that both water and methanol absorb light in the second wavelengthband 605.

For some embodiments, the water detector utilizes only one of the secondand fifth wavelength bands 606, 609 or other wavelength bands alsoassociated with absorption by water, in particular, bands that haveabsorption characteristics in water equivalent to or greater than thefifth wavelength band 609. Any absorption detected at the second orfifth wavelength band 606, 609 can thereby indicate a presence of water.The amount of absorption can correlate (e.g., Beer's Law) to thequantity of water present.

Concurrent measurements at wavelengths off water absorbent peaks such asone or more of the first, third and fourth wavelength bands 605, 607,608 enables correcting signals indicative of absorbance measured at oneor both of the second and fifth wavelength bands 606, 609 fornon-wavelength dependent attenuation such as previously describedherein. Signal attenuation results from water absorption, oil absorptionor scattering since the gas phase is relatively non-absorbent.Accordingly, ratiometric based measurements utilizing the concurrentmeasurements enables quantifying and correcting for this scatteringportion so the presence of water can be accurately detected and/or awater to oil ratio can be determined.

Monitoring of the fifth wavelength band 609 at around 1950 nm enablesdifferentiation of water from any injected methanol used to inhibithydrate formation since the methanol only has a carbon to hydroxyl bondthat does not provide the same water molecule deformation that causesabsorption at around 1950 nm. This ability to differentiate the methanolfrom water permits detection of the water even during hydrate inhibitorinjection. Additionally, detection of the amount of water being producedenables determination of whether the hydrate inhibitor is sufficientgiven the quantity of the inhibitor selected to be injected.

In addition, monitoring the fifth wavelength band 609 or an equivalentband with respect to water absorption characteristics causes sufficientattenuation at concentrations of water even below 0.1% to enable use ofthe water detector for flow assurance in critical well applicationswhere hydrate formation possibilities exist. Therefore, spectralanalysis of the fifth wavelength band 609, for example, enables this lowlevel moisture detection. However, other wavelength bands less absorbedby water than the fifth wavelength band 609 may be suitable for higherwater concentrations once presence of water is known or determined suchas by measurement of any attenuation at the fifth wavelength band 609,which attenuation may tend to absorb all input light at the fifthwavelength band 609 causing saturation that inhibits any furtherdeterminations based off readings associated with the fifth wavelengthband 609.

FIG. 7 illustrates a flow chart of a flow processing technique to detecta presence of water utilizing the water detector. At signal receipt step702, electronics receive signals from at least one channel of the waterdetector. The at least one channel corresponds to a water absorbentwavelength band such as the fifth wavelength band 609. An algorithm atdetection step 704 identifies a presence of water and/or determines aquantification or phase fraction of the water based on absorbancereadings from the signals. An alarm, visual output or automatedcorrective action can initiate upon detecting the water so that, forexample, appropriate reductions in producing rate or methanol injectionscan be made.

Detection of signals corresponding to concurrent measurements atwavelengths off water absorbent wavelength peak(s) can occur atadditional channel step 706. At correction step 708, an algorithm cancorrect the signals for non-wavelength dependent attenuation based oninfluences effecting signals from each channel indiscriminately suchthat the non-wavelength dependent attenuation drops out in the detectionstep 704. A methanol indicating step 710 can compare signalscorresponding to the water absorbent wavelength band(s) with a signalthat also corresponds to a methanol absorption band such as the secondwavelength band 606. The comparison from the methanol indicating step710 can enable differentiation between water and methanol measurements.

The preferred embodiments use the broad band source and the filters toisolate wavelengths associated with the channels. However, otherembodiments of the phase fraction meter include separate narrow bandsources, tunable filters, and/or a single source that is swept for thedesired wavelengths of the channels.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. An infrared water detector for monitoring a hydrocarbon well,comprising: a source for emitting into a flow stream infrared light thatincludes first and second water absorbent wavelength bands and asubstantially transmissive wavelength band with respect to water,wherein the water absorbent wavelength bands have different absorptioncoefficients for water and a hydrate inhibitor; a detector for detectingattenuation of the wavelength bands upon the infrared light passingthrough at least a portion of the flow stream; and an output indicativeof a presence of water as determined based on the attenuation of thewavelength bands.
 2. The water detector of claim 1, wherein the outputis further indicative of a quantity of water as determined based on theattenuation of the wavelength bands.
 3. The water detector of claim 2,wherein one of the water absorbent wavelength bands is around 1950 nm.4. The water detector of claim 1, wherein one of the water absorbentwavelength bands is around 1950 nm.
 5. The water detector of claim 1,wherein the first and second water absorbent wavelength bands are around1450 nm and 1950 nm, respectively.
 6. The water detector of claim 1,wherein the detector simultaneously detects the attenuation of theabsorbent and transmissive wavelength bands.
 7. The water detector ofclaim 1, wherein the light source is a broad band light source.
 8. Thewater detector of claim 1, wherein the infrared light after passingthrough the at least the portion of the flow stream is received bygroups of optical fibers, wherein individual optical fibers within atleast one of the groups of optical fibers are arranged such that eachindividual fiber receives light transmitted across a discrete lightpath, through the at least the portion of the flow stream, that isdifferent from a light path of adjacent fibers.
 9. A method of detectingwater within a flow stream of a hydrocarbon well, comprising: emittinginfrared light into the flow stream, the infrared light including firstand second water absorbent wavelength bands and a substantiallytransmissive wavelength band with respect to water, wherein the waterabsorbent wavelength bands have different absorption coefficients forwater and a hydrate inhibitor; detecting attenuation of the waterabsorbent wavelength bands upon the infrared light passing through atleast a portion of the flow stream; correcting the attenuation of thewater absorbent wavelength bands detected based on detection ofattenuation of the transmissive wavelength band; and determining apresence of water based on the attenuation of the water absorbentwavelength bands after being corrected.
 10. The method of claim 9,further comprising disposing a water detector along a conduit containingthe flow stream of the hydrocarbon well.
 11. The method of claim 9,further comprising disposing a water detector subsea along a conduitcontaining the flow stream of the hydrocarbon well.
 12. The method ofclaim 9, further comprising disposing a water detector within a wellborealong a conduit containing the flow stream of the hydrocarbon well. 13.The method of claim 9, further comprising quantifying water in the flowstream based on the attenuation of the water absorbent wavelength bandsafter being corrected.
 14. The method of claim 9, wherein detecting theattenuation of the absorbent wavelength bands occurs simultaneously withdetecting the attenuation of the transmissive wavelength band.
 15. Themethod of claim 9, wherein one of the water absorbent wavelength bandsis around 1950 nm.
 16. The method of claim 9, further comprisingadjusting an operating parameter of the well upon determining water ispresent.
 17. The method of claim 16, wherein adjusting the operatingparameter comprises one of adjusting a production rate or adjustinginjection of the hydrate inhibitor.
 18. The method of claim 9, whereinthe infrared light after passing through the at least the portion of theflow stream is received by groups of optical fibers, wherein individualoptical fibers within at least one of the groups of optical fibers arearranged such that each individual fiber receives light transmittedacross a discrete light path, through the at least the portion of theflow stream, that is different from a light path of adjacent fibers. 19.The method of claim 9, further comprising comparing the attenuation ofthe water absorbent wavelength bands after being corrected todifferentiate between measurements of the water and of the hydrateinhibitor.